Rock permeability is one, if not the most, important parameter to know when it comes to understanding natural and engineered flows in the permeable subsurface. Likewise it is crucial to quantify changes in rock permeability, e.g., due to reservoir stimulation through hydraulic or propellant fracturing. Permeability fields in fractured rock are highly heterogeneous with most of the flow concentrated on transmissive fracture networks. Nonetheless fractures can be rather space-filling, and therefore the transmissive fracture network which predominantly participates in subsurface flow can be rather space filling too. FIG. 1A is a map view of a Tomographic Fracture Image (TFI™) of a space-filling fracture network at the reservoir scale. However, it is also possible that there are localized conduits for fluid flow, which can, for example, be linked to fault zones. FIG. 1B illustrates a graphical view of localized zones with relatively high permeability.
Reservoir-scale permeability is an extremely difficult parameter to measure in the deep subsurface. Rock core permeabilities are not representative of the permeabilities of the reservoir-scale fracture networks, which typically exceed the matrix permeability of the cores by orders of magnitude. Pumping tests [e.g., pressure transient analysis (PTA)], in which fluid is injected or withdrawn from a well while changes in borehole pressure are monitored, are not reliable for the low permeabilities often encountered at depth or yield a permeability that is representative only for a small rock volume in the vicinity of the borehole.
Recent advances in rock imaging technology now allow not only mapping the fracture network in the deep subsurface but also identifying dominant flow paths associated with transmissive fracture/fault systems. This is possible through the usage of TFI™, which processes passive seismic data from buried and surface based seismic networks via Seismic Emission Tomography (SET). TFI™ can be used to image directly the dynamic behavior of fracture/fault systems at scales ranging from 10 meters to kilometers. Therefore TFI™ generates five dimensional (5D) semblance data, i.e., the 3D position, time, and seismic energy. TFI™ has, for example, been used to monitor fracture growth during hydraulic fracturing.
Using TFI™, it has been possible to observe slow fluid pressure waves induced by pressurization of a borehole due to the injection of slurries. These so-called Pf waves propagate with a speed on the order of 10 m/s through the transmissive fracture/fault network. The rock domain, which the Pf wave excites, is associated with high-permeability zones within the transmissive fracture network. Due to the small velocity of the Pf waves, it is clear that they are not regular compressional or shear waves, which in natural subsurface environments have velocities on the order of one thousand m/s (e.g., 500 m/s; 1,000 m/s; 2,000 m/s; etc.). So far, a theoretical explanation for the Pf wave has not been provided. Therefore, it is currently not possible to determine rock parameters from the measured speed and attenuation of the Pf wave.
Accordingly, there is a need in the art for a method to estimate the permeability of fractured rock formations from the analysis of a slow fluid pressure wave.